Hydroprocessing process

ABSTRACT

A process for hydroprocessing a hydrocarbon feedstock includes the steps of providing a hydrocarbon feed having an initial characteristic; providing a first hydrogen-containing gas; feeding the hydrocarbon feed and the first hydrogen-containing gas cocurrently to a first hydroprocessing zone so as to provide a first hydrocarbon product; providing a plurality of additional hydroprocessing zones including a final zone and an upstream zone; feeding the first hydrocarbon product cocurrently with a recycled gas to the upstream zone so as to provide an intermediate hydrocarbon product; and feeding the intermediate hydrocarbon product cocurrently with a second hydrogen-containing gas to the final zone so as to provide a final hydrocarbon product having a final characteristic which is improved as compared to the initial characteristic.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. patent application Ser. No.10/719,590 filed Nov. 21, 2003, now U.S. Pat. No. 7,166,209, which is acontinuation-in-part of U.S. patent application Ser. No. 09/960,442,filed Sep. 24, 2001, now U.S. Pat. No. 6,656,348, which is acontinuation-in-part of U.S. patent application Ser. No. 09/797,448filed Mar. 1, 2001, now U.S. Pat. No. 6,649,042.

BACKGROUND OF THE INVENTION

The invention relates to a deep hydroprocessing process and, moreparticularly, to a process for effectively treating a hydrocarbonfeedstock, especially for hydrocoversion processes such as processes forremoving contaminant such as sulfur from hydrocarbon feedstocks.

A persistent problem in the art of petroleum refining is to reachacceptably low levels of contaminants such as sulfur and others.

A large portion of the world's hydrocarbon reserves contain sulfur, andremoval of this sulfur is critical in order to provide acceptable fuels.

Government agencies are currently formulating new regulations which willrequire sulfur content in fuels to be substantially lower than currentpractice. It is expected that such regulations will require sulfurcontent of less than 15 wppm.

A number of processes have been attempted for use in removing sulfur,one of which is hydrodesulfurization, wherein a hydrogen flow is exposedto the feedstock in the presence of a suitable catalyst so that sulfurcompounds react to produce a volatile product, hydrogen sulfide.

Such processes do provide substantial reduction in sulfur in the feed.However, existing facilities do not readily provide for reduction ofsulfur content to desired levels. Known hydrodesulfurization methodsinclude cocurrent processes, wherein hydrogen and hydrocarbon feed arefed through a reactor or zone in the same direction, and countercurrentprocesses wherein hydrocarbon is fed in one direction and gas is fed inthe other direction.

Known cocurrent processes do not provide acceptable levels of sulfurremoval, and countercurrent processes typically experience difficulty inreactor flooding which occurs when the desired amount of gas flow to thereactor prevents flow of the hydrocarbon in the counter direction.Reduction of gas flow to address flooding reduces the effectiveness ofcountercurrent hydrodesulfurization processes.

Another potential problem with countercurrent processes is thatadiabatic countercurrent processes may operate at temperatures muchhigher than adiabatic cocurrent processes, and this temperature isdetrimental to hydrodesulfurization and other catalysts used in theprocess.

Based upon the foregoing, it is clear that the need remains for anadvantageous process for removal of sulfur to levels which will meet theexpected regulations on hydrocarbons for use as fuel.

It is also clear that the need remains for an improved process wherebyflooding and temperature issues can be resolved.

It is therefore the primary object of the present invention to provide aprocess whereby sulfur content is advantageously reduced to less than orequal to about 10 wppm.

It is a further object of the present invention to provide a processwhich can be carried out without substantially increasing the equipmentsize and space occupied by same in current hydroconversion systems.

It is still another object of the present invention to provide ahydroconversion system which accomplishes the aforesaid objectives.

Other objects and advantages of the present invention will appearhereinbelow.

SUMMARY OF THE INVENTION

In accordance with the present invention, the foregoing objects andadvantages have been readily attained.

In accordance with the invention a process is provided for upgrading ahydrocarbon feedstock, which process comprises the steps of providing ahydrocarbon feed having an initial characteristic; providing a firsthydrogen-containing gas; feeding said hydrocarbon feed and said firsthydrogen-containing gas cocurrently to a first hydroprocessing zone soas to provide a first hydrocarbon product; providing a plurality ofadditional hydroprocessing zones including a final zone and an upstreamzone; feeding said first hydrocarbon product cocurrently with a recycledgas to said upstream zone so as to provide an intermediate hydrocarbonproduct; and feeding said intermediate hydrocarbon product cocurrentlywith a second hydrogen-containing gas to said final zone so as toprovide a final hydrocarbon product having a final characteristic whichis improved as compared to said initial characteristic.

Still further according to the invention, a system is provided forupgrading a hydrocarbon feed, which system comprises a firsthydroprocessing zone containing a hydroprocessing catalyst and having aninlet for cocurrently receiving a hydrocarbon feed and a firsthydrogen-containing gas phase; a plurality of additional hydroprocessingzones each containing a hydroprocessing catalyst and including a finalzone and an upstream zone, said upstream zone having an inlet forcocurrently receiving a hydrocarbon product from said firsthydroprocessing zone and a recycled hydrogen-containing gas phase, saidfinal zone having an inlet for cocurrently receiving a hydrocarbonproduct from said upstream hydroprocessing zone cocurrently with asecond hydrogen-containing gas phase; and a separator for receiving aproduct from said final hydroprocessing zone and for separating saidproduct into a hydrocarbon phase and said recycled hydrogen-containinggas phase.

The process and system of the present invention are particularly wellsuited for use in treating Diesel, gasoil and other distillatefeedstocks to reduce sulfur and also for use in treating naphtha andlike feedstocks as well.

Other processes which can be carried out using the flow scheme of thepresent invention include the combination of hydrodesulfurization in thefirst reactor and carrying out of a second type of reaction process inthe downstream reactor, for example hydrocracking of heavy hydrocarbonfeedstocks to lower boiling products; hydrocracking of distillate andhigher boiling range feedstocks; hydrogenation of aromatics;hydroisomerization; hydrodewaxing, especially of Fischer-Tropsch waxes;and removal of metal from heavy streams. All of these processes benefitfrom major removal of product gases such as hydrogen sulfide and ammoniain the inter-reactor gas-liquid separator.

BRIEF DESCRIPTION OF THE DRAWINGS

A detailed description of preferred embodiments of the present inventionfollows, with reference to the attached drawings, wherein:

FIG. 1 schematically illustrates a process and system in accordance withthe present invention;

FIG. 2 schematically illustrates an alternative embodiment of theprocess and system in accordance with the present invention;

FIG. 3 illustrates the temperature of a process as a function of reactorlength for cocurrent and countercurrent processes, as well as theprocess of the present invention;

FIG. 4 illustrates the relationship of sulfur content and relativereactor volume for a process according to the present invention and aglobally countercurrent process;

FIG. 5 illustrates sulfur content as a function of relative reactorvolume for processes according to the present invention with and withoutcold separator recycling;

FIG. 6 illustrates the relationship between outlet sulfur content andrelative reactor volume for a process according to the presentinvention, a pure cocurrent process, and a two-reactor inter-stagestripping process;

FIG. 7 illustrates the relationship between outlet sulfur content andrelative reactor volume for a process according to the present inventionand for a process having different ratio of hydrogen distribution;

FIG. 8 illustrates the relationship between outlet sulfur content andrelative reactor volume for a process according to the present inventionand for a process having and inverse distribution of catalyst betweenfirst and second stages;

FIG. 9 illustrates the relationship between dimensionless reactor lengthand hydrogen partial pressure for a process according to the presentinvention and a pure cocurrent process;

FIG. 10 illustrates the relationship between dimensionless reactorlength and reactor temperature for a process according to the presentinvention as well as pure cocurrent and pure countercurrent processes;and

FIG. 11 illustrates the relationship between outlet sulfur content andrelative reactor volume for a process according to the present inventionas well as a pure cocurrent and pure countercurrent process.

DETAILED DESCRIPTION

In accordance with the present invention, a hydroprocessing process andsystem are provided for treatment of a hydrocarbon feedstock, forexample for removal of contaminants, especially sulfur from ahydrocarbon feed such as Diesel, gasoil, naphtha and the like. Aparticularly advantageous aspect of the present invention ishydrodesulfurization, and the following detailed description is given asto a hydrodesulfurization process. Of course, the invention is equallysuited to processes which involve contacting a hydrocarbon feed with ahydrogen-containing gas to upgrade some other aspect of the feedstock.

The process and system of the present invention in connection with ahydrodesulfurization process advantageously allow for reduction ofsulfur content to less than or equal to about 10 wppm, which is expectedto satisfy regulations currently proposed by various Governmentagencies, without requiring substantial expense for new equipment,additional reactors, and the like.

In accordance with the invention, a first hydroprocessing zone isprovided along with a plurality of additional hydroprocessing zones, andhydrogen-containing gases fed to theses zones so as to advantageouslyupgrade a hydrocarbon feedstock.

In accordance with one aspect of the present invention, the hydroprocessprocess carried out in all of these zones is primarilyhydrodesulfurization, and the operating perimeters of each zone aretailored toward removal of sulfur in each stage.

In accordance with a further aspect of the present invention, thedownstream hydroprocessing zones can be other processes, especiallyother processes which can benefit from upstream removal of sulfur. Inthis instance, the first hydroprocessing zone can be ahydrodesulfurization zone, while the downstream hydroprocessing zonescan be other types of reaction processes such as hydrocracking,hydrogenation of aromatics, hydroisomerization, hydrodewaxing, metalremoval and the like.

It should also be noted that the upstream hydroprocessing zone can betailored for other hydroprocessing goals such as removal of ammonia(NH₃), either as a primary goal or as a secondary goal in addition toremoval of sulfur.

In accordance with one embodiment of the present invention, a process isprovided which combines a single cocurrently operatedhydrodesulfurization reactor with a second stage including a pluralityof hydrodesulfurization reactors to obtain a desired result. As will befurther discussed below, the second stage includes a plurality ofadditional hydrodesulfurization reactors or zones and is operated in aglobally countercurrent, yet locally cocurrent, mode. This means thatwhen considered on the basis of the reactors overall, the hydrocarbonand hydrogen-containing gas are fed in opposite directions. However,each reactor or zone is coupled so as to flow the hydrocarbon andhydrogen-containing gas in a cocurrent direction within that reactor,thereby providing the benefits of globally countercurrent flow, whileavoiding the flooding problems which might be experienced with localcountercurrent flow through a reactor zone.

The reactors within the second stage are arranged such that thehydrocarbon feedstock travels from a first reactor to a last or finalreactor, and the hydrogen gas phase travels from the last reactor to thefirst reactor. In the following detailed description, the group ofreactors that are utilized in the second zone are referred to asincluding a final reactor, from which the finally treated hydrocarbonexits, and upstream reactors which are upstream of the final reactorwhen taken in connection with the flow of hydrocarbon. Thus, in FIG. 1,reactor 28 is upstream from reactor 30 when considered in light of thedirection of hydrocarbon flow, and in FIG. 2, reactor 52 is upstream ofreactor 54, and reactor 50 is upstream of both reactors 52 and 54, alsowhen considered in connection with the direction of hydrocarbon flow.Thus, as used herein, an upstream reactor is a reactor which is upstreamas it relates to hydrocarbon flow.

In accordance with the present invention, the hydrodesulfurization stepsto be carried out are accomplished by contacting or mixing thehydrocarbon feed containing sulfur with a hydrogen gas-containing phasein the presence of a hydrodesulfurization catalyst and athydrodesulfurization conditions whereby sulfur species within thehydrocarbon convert to hydrogen sulfide gas which remains with thehydrogen gas phase upon separation of liquid and gas phases. Suitablecatalyst for use in hydrodesulfurization processes are well known to aperson of ordinary skill in the art, and selection of the particularcatalyst forms no part of the present invention.

In connection with the gas phase, suitable gas contains hydrogen asdesired for the hydroprocessing reaction. This gas may be substantiallypure hydrogen or may contain other gases, so long as the desiredhydrogen is present for the desired reaction. Thus, as used herein,hydrogen-containing gas includes substantially pure hydrogen gas andother hydrogen-containing streams.

Turning now to FIG. 1, a hydrodesulfurization process in accordance withthe present invention is schematically illustrated.

As shown, the process is carried out in a first stage 10 and a secondstage 12, so as to provide a final hydrocarbon product having acceptablylow content of sulfur.

As shown, first stage 10 is carried out utilizing a first reactor 14 towhich is fed a hydrocarbon feed 16 containing an initial amount ofsulfur. Feed 16 is combined with a hydrogen-containing gas 18 and fedcocurrently through reactor 14 such that cocurrent flow of hydrocarbonfeed 16 and gas 18 in the presence of hydrodesulfurization catalyst andconditions converts sulfur species within the hydrocarbon into hydrogensulfide within the product 20 of reactor 14. Product 20 is fed to aliquid gas separator 22 where a predominantly hydrogen and hydrogensulfide containing gas phase 24 is separated from an intermediateproduct 26. Intermediate product 26 has a reduced sulfur content ascompared to hydrocarbon feed 16, and is fed to second stage 12 inaccordance with the present invention for further treatment to reducesulfur content and/or other types of processing as referred to above.

As shown, second stage 12 preferably includes a plurality of additionalreactors 28, 30, which are connected in series for treating intermediateproduct 26 as will be further discussed below. As shown, reactor 28preferably receives intermediate hydrocarbon feed 26 which is mixed witha recycled hydrogen gas 31 and fed cocurrently through reactor 28.Product 32 from reactor 28 is then fed to a liquid gas separator 34 forseparation of a predominately hydrogen and hydrogen sulfide containinggas phase 36 and a further treated liquid hydrocarbon product 38 havinga sulfur content still further reduced as compared to intermediatehydrocarbon feed 26. Hydrocarbon feed 38 is then fed to reactor 30,combined with an additional hydrogen feed 40 and fed cocurrently withhydrogen feed 40 through reactor 30 to accomplish still furtherhydrodesulfurization and produce a final product 42 which is fed to aseparator 44 for separation of a gas phase 46 containing hydrogen andhydrogen sulfide as major components, and a final liquid hydrocarbonproduct 48 having substantially reduced Sulfur content.

Alternatively, catalyst and conditions within additional reactors 28, 30can be tailored to focus predominantly on other types of hydroprocessingreactions, for example hydrocracking, hydrogenation of aromatics,hydroisomerization, hydrodewaxing, removal of metals and the like. Theappropriate catalysts for obtaining these processes, as well as theappropriate conditions for same, are well known to a person or ordinaryskill in the art.

In accordance with the present invention, gas phase 46 is recycled foruse as recycled gas 31 such that gas flowing through the reactors ofsecond stage 12 is globally countercurrent to the flow of hydrocarbonthrough same. Considering the flow of hydrocarbon from reactor 28 toreactor 30, it is readily apparent that reactor 28 is an upstreamreactor and reactor 30 is a final reactor of second stage 12. It shouldof course be appreciated that additional upstream reactors could beincluded in second stage 12 if desired, and that second stage 12preferably includes at least two reactors 28, 30 as shown in thedrawings. However, it is a particular advantage of the present inventionthat excellent results are obtained utilizing the first and secondstages as described above with a like number of reactors as arecurrently used in conventional processes, thereby avoiding the need foradditional equipment and space.

It should also be appreciated that although FIG. 1 shows reactors 14, 28and 30 as separate and discrete reactors, the process of the presentinvention could likewise be carried out by defining different zoneswithin a collectively arranged reactor, so long as the zones areoperated with flow of feed and gas as described above for the first andsecond stages, with local cocurrent flow through each zone of bothstages and globally countercurrent flow through the at least two zonesof second stage 12.

Turning now to FIG. 2, a further embodiment of the present invention isillustrated.

As shown, first stage 10 includes a single reactor 14 in similar fashionto the embodiment of FIG. 1.

Second stage 12 in this embodiment includes reactors 50, 52, and 54, andeach reactor is operated in a similar fashion to the second stagereactors of the embodiment of FIG. 1 so as to provide a single cocurrentstage in first stage 10 and a globally countercurrent, locally cocurrentprocess in second stage 12. Thus, feed 56 and fresh hydrogen-containinggas 58 are fed cocurrently to reactor 14 so as to produce product 60which is fed to separator 62 to produce an intermediate liquidhydrocarbon product 64 and gas phase 66 containing hydrogen and hydrogensulfide as major components. Intermediate hydrocarbon product 64 is thenfed to second stage 12, where it is mixed with recycled gas 68 and fedcocurrently through reactor 50 to produce product 70 which is fed toseparator 72. Separator 72 separates a further intermediate liquidhydrocarbon product 74 and a gas phase 76 containing hydrogen andhydrogen sulfide as major components.

Intermediate hydrocarbon product 74 is then combined with recycledhydrogen 78 and fed to reactor 52, cocurrently, so as to produce afurther intermediate product 80 which is fed to separator 82 forseparation of a further liquid hydrocarbon feed 84 and a gas phase 86containing hydrogen and hydrogen sulfide as major components which areadvantageously fed to upstream reactor 50 as recycled gas 68.Hydrocarbon product 84 is then advantageously combined with a freshhydrogen feed 88 and fed to last reactor 54, cocurrently, for furtherhydrodesulfurization so as to provide product 90 which is fed toseparator 92 for separation of hydrocarbon liquid phase 94 and gas phase96 containing hydrogen and hydrogen sulfide as major components.Advantageously, gas phase 96 is fed to upstream reactor 52 and recycledas recycled gas 78 for use in that process, while liquid phase 94 can betreated as a final product, or alternatively can be treated further asdiscussed below.

In accordance with one aspect of the present invention, ahydrodesulfurization catalyst is present in each reactor, and eachsuccessive hydrocarbon product has a sulfur content reduced as comparedto the upstream hydrocarbon feed. Further, the final hydrocarbon producthas a final sulfur content which is substantially reduced as compared tothe initial feed, and which is advantageously less than or equal toabout 10 wppm so as to be acceptable under new regulations from variousGovernment agencies.

Further, it should be readily apparent that second stage 12 of theembodiment of FIG. 2 is globally countercurrent, as with the embodimentof FIG. 1. Specifically, hydrocarbon is fed from reactor 50 to reactor52 and finally to final reactor 54, while gas phase is fed from reactor54 to reactor 52 and finally to reactor 50. This provides for theadvantages of a globally countercurrent process, while avoiding floodingproblems which could occur with locally countercurrent processes.

Still referring to FIG. 2, it may be desirable to feed gas phases 66 and76 to a low temperature separator 98 which operates to remove volatilehydrocarbon product 100, which can be recycled back as additional feed56 for further treatment in accordance with the process of the presentinvention, with a purge stream 101 also as shown. Low temperatureseparator 98 also separates a gas phase 102 which can advantageously bemixed with final product 94 and fed to a final separator 104 so as toobtain a further treated final hydrocarbon product 106 and a final gasphase 108 containing hydrogen and the bulk of removed sulfur. Product106 can be further treated for enhancing various desired qualities as ahydrocarbon fuel, or can be utilized as hydrocarbon fuel without furthertreatment, since the sulfur content has been advantageously reduced toacceptable levels.

Final gas phase 108 can advantageously be fed to a stripper or othersuitable unit for removal of hydrogen sulfide to provide additionalfresh hydrogen for use as hydrogen feeds 58 or 88 in accordance with theprocess of the present invention.

It should readily be appreciated that FIGS. 1 and 2 further illustrate asystem for carrying out the process in accordance with the presentinvention.

Typical feed for the process of the present invention includes Diesel,gasoil and naphtha feeds and the like. Such feed will have anunacceptably high sulfur content, typically greater than or equal toabout 10 wppm. The feed and total hydrogen are preferably fed to thesystem at a global ratio of gas to feed of between about 500 scfb andabout 4000 scfb (std. cubic feet/barrel). Further, each reactor maysuitably be operated at a temperature of between about 300° C. and about420° C., and a pressure of between about 400 psi and about 1500 psi.

In accordance with the present invention, it should readily beappreciated that catalyst volume and gas streams are distributed betweenthe first zone and the second zone. In accordance with the presentinvention, the most suitable distribution of gas catalyst is determinedutilizing an optimization process. It is preferred, however, that thetotal catalyst volume be distributed between the first zone and thesecond zone with between about 20 and about 80% volume of the catalystin the first zone and between about 80 and about 20% volume of thecatalyst in the second zone. Further, as discussed above, the totalhydrogen is fed to the system of the present invention with one portionto the first zone and the other portion to the final reactor of thesecond zone. It is preferred that between about 20 and 70% volume of thetotal hydrogen for the reaction be fed to the first zone, with thebalance being fed to the final reactor of the second zone.

It should be noted that as with all hydrodesulfurization processes, thehydrodesulfurization catalyst will gradually lose effectiveness overtime, and this can be advantageously countered in the process of thepresent invention by increasing gas flow rate if desired. This ispossible with the process of the present invention because locallycocurrent flow is utilized, thereby preventing difficulties associatedwith flooding and the like in locally countercurrent processes.

It should also be appreciated that the process of the present inventioncan advantageously be used to reduce sulfur content of naphtha feed. Insuch processes, condensers would advantageously be positioned after eachreactor, rather than separators, so as to condense the reduced sulfurnaphtha hydrocarbon product while maintaining the gas phase containinghydrogen and hydrogen sulfide as major components. In all otherrespects, this embodiment of the present invention will function in thesame manner as that described in connection with FIGS. 1 and 2.

Turning now to FIG. 3, and as set forth above, the process of thepresent invention combining in a hybrid fashion a first stage purelycocurrent reaction and a second stage which is globally countercurrentand locally cocurrent advantageously provides for operation of thereactors at reduced temperatures as compared to countercurrentprocesses. FIG. 3 illustrates temperature as a function of dimensionlessreactor length for a typical cocurrent process, for a countercurrentprocess, and for a hybrid process in accordance with the presentinvention. As shown, the temperature in the countercurrent process issubstantially higher than the hybrid process of the present invention,with the result that the catalyst of the hybrid process of the presentinvention is subjected to less severe and damaging conditions.

In accordance with the present invention, improved results are obtainedusing the same amounts of catalyst and hydrogen as a conventionalcountercurrent or cocurrent process. In accordance with the presentinvention, however, the hydrogen feed is divided into a first portionfed to the first stage and a second portion fed to the second stage, andthe catalyst volume is also divided between the first stage and secondstage, which are operated as discussed above, so as to provide improvedhydrodesulfurization as desired.

As set forth above, one particularly advantageous hydrocarbon feed withwhich the process of the present invention can be used is a gasoil feed.In a typical application, a reactor can be provided having a reactordiameter of about 3.8 meters, a reactor length of about 20 meters, and acocurrent feed of hydrogen to gasoil at a ratio of hydrogen gas togasoil of about 270 Nm³/m³, a temperature of about 340° C., a pressureof about 750 psi and a liquid hourly space velocity (LHSV) through thereactor of about 0.4 h⁻¹.

The gasoil may suitably be a vacuum gasoil (VGO) an example of which isdescribed in Table 1 below.

TABLE 1 API gravity (60° C.) 17.3 Molecular weight (g/mol) 418 Sulfurcontent, % wt 2 Simulated Distillation (° C.) IBP/5, % v 236/366 10/20,% v 392/413 30/50, % v 431/454 70/80, % v 484/501 90/95, % v 522/539 FBP582

For such a feedstock, easy-to-react (ETR) sulfur compounds would be, forexample, 1-butylphenantrothiophene. When contacted with hydrogen atsuitable conditions, this sulfur compound reacts with the hydrogen toform hydrogen sulfide and butylphenantrene. A typical difficult-to-react(DTR) sulfur compound in such a feed is heptyldibenzothiophene. Whencontacted with hydrogen gas under suitable conditions, this reacts toform hydrogen sulfide and heptylbiphenyl.

It should of course be appreciated that although the above descriptionis given in terms of hydrodesulfurization processes, the hybrid processof the present invention is readily applicable to other hydroprocessingsystems, and can advantageously be used to improve hydroprocessingefficiency in various different processes while reducing problemsroutinely encountered in the art. Other processes which can be carriedout using the flow scheme of the present invention include thecombination of hydrodesulfurization in the first reactor and carryingout of a second type of reaction process in the downstream reactor, forexample hydrocracking of heavy hydrocarbon feedstocks to lower boilingproducts; hydrocracking of distillate and higher boiling rangefeedstocks; hydrogenation of aromatics; hydroisomerization;hydrodewaxing, especially of Fischer-Tropsch waxes; and removal of metalfrom heavy streams. All of these processes benefit from major removal ofproduct gases such as hydrogen sulfide and ammonia in the inter-reactorgas-liquid separator.

EXAMPLE 1

A VGO feed as described in Table 1 was used with a series of differenthydrodesulfurization processes, and conversion of sulfur compounds andsulfur in the final product were modeled for each case. The results areset forth in Table 2 below.

TABLE 2 VGO Gas Flow CONVERSION Flow rate rate % % S (wt.) REACTORVOLUME LHSV CASE (BBL/D) Nm³/h C₄FT^((ETR)) C₆DBT^((DTR)) OUTLET (m³)(h⁻¹) CASE 1 2000 35162 94.14 75.74 0.19 322 0.4 L = 28 m CASE 2 2000035162 98.79 98.37 0.0256 322 R1 = R2 = . . . = Rn L = 28 m n = 20 CASE 320000 35162 99.3 95.9 0.0271 322 0.4 L = 28 R1 = R2 = R3 CASE 4 2000035162 98.99 90.259 0.053 322 0.4 L = 28 R1 = R2 CASE 5 20000 First 99.897 0.016 322 0.4 26371.5 L = 28 m Last R = 60% L 8790.5 R2 = R3 = 20% LCASE 6 20000 First 99.93 99.5 0.00317 483 0.27 26371.5 Last 8790.5 CASE7 20000 35162 99.9 99.2 0.00313 L = 133 m 0.09 1508 CASE 8 20000 First99.9 99.7 0.0021 962 0.14 26371.5 Last 8790.5 CASE 9 20000 35162 99.996.4 0.0162 962 0.14 R1, L = 28 m, D = 3.8, R2, L-20.86 m, D = 4.42 m,R2, L = 20.86 m, D = 4.42 m CASE 10 20000 35162 99.9 99.5 0.00312 9620.14 R1, L = 28 m, D = 3.8, R2, L = 20.86 m, D = 4.42 m, R2, L = 20.86m, D = 4.42 m where D = diameter; R = length of reactor; and L = totallength.

In Table 2, cases 5, 6 and 8 are carried out in accordance with theprocess of the present invention. For comparison purposes, cases 1 and 7were carried out utilizing a single reactor through which were fed,cocurrently, VGO and hydrogen.

Case 2 was carried out utilizing 20 reactors arranged for globallycountercurrent and locally cocurrent flow as illustrated in the secondstage portion of FIG. 1.

Cases 3 and 10 were also carried out utilizing globally countercurrentand locally cocurrent flow as in stage 2 alone of FIG. 1.

Case 4 was carried out utilizing two reactors with an intermediatehydrogen sulfide separation stage, and case 9 was carried out utilizingpure cocurrent flow, globally and locally, through three reactors.

At the flow rates shown, results were modeled and are set forth in Table2.

Cases 1-5 were all carried out utilizing reactors having a volume of 322m³, and at the same VGO and gas flow rates. As shown, case 5, utilizingthe two stage hybrid process of the present invention, provided the bestresults in terms of conversion of sulfur compounds and sulfur remainingin the final product. Further, this substantial improvement inhydrodesulfurization was obtained utilizing the same reactor volume, andcould be incorporated into an existing facility utilizing anyconfiguration of cases 1-4 without substantially increasing the areaoccupied by the reactors.

Case 6 in Table 2 shows that by reasonable increase in reactor volume,still further advantageous results can be obtained in accordance withthe process of the present invention, and final sulfur content wouldsatisfy the strictest of expected regulations in connection with maximumsulfur content, and this is accomplished through only a small increasein reactor volume.

Case 7 of Table 2 shows that in order to accomplish similar sulfurcontent results to case 6, a single reactor operated in a singlecocurrent conventional process would require almost 4 times the reactorvolume as case 6 in accordance with the process of the presentinvention.

Cases 8, 9 and 10 are modeled for a reactor having a volume of 962 m³,and the hybrid process of the present invention (Case 8) clearly showsthe best results as compared to Cases 9 and 10.

In accordance with the foregoing, it should be readily apparent that theprocess of the present invention is advantageous over numerousalternative configurations.

EXAMPLE 2

In this example, a Diesel feed was treated utilizing several differentprocess schemes and, sulfur compound conversion and sulfur content inthe final product were calculated. The Diesel for this example hadcharacteristics as follows:

Diesel API = 27 MW = 213 Sulfur = 1.10% wt Simulated Distillation(° C.)IBP-5 177/209 10-20 226/250 30-40 268/281 50-60 294/308 70-80 323/33990-95 357/371 FBP 399

Table 3 below sets forth the process conditions and results of eachcase.

TABLE 3 Diesel Flowrate Gas Flow rate CONVERSION % S (wt) REACTOR LHSVCASE (BBL/D) Nm³/h EDBT^((ETR)) DMDBT^((DTR)) OUTLET VOLUME (m³) (h⁻¹)CASE 1 35000 24039 96.5 81.6 0.072 370 0.63 L = 35 m CASE 2 35000 2403993.72 93.44 0.07 370 0.63 R1 = R2 . . . = Rn L = 35 m n = 20 CASE 335000 First 99.28 96.8 0.0135 370 0.63 18029 L = 35 m Last R1 = 60% L6010 R2 = R3 = 20% L CASE 4 35000 24039 96.52 81.6 0.072 370 0.63 L = 35m CASE 5 72000 First 96.08 82.53 0.074 370 1.3 37097 L = 35 m Last 12366

Case 1 of Table 3 was carried out by cocurrently feeding a Diesel andhydrogen feed through a single reactor having the shown length andvolume.

Case 2 was carried out feeding Diesel and hydrogen globallycountercurrently, and locally cocurrently, through 20 reactors havingthe same total length and volume as in Case 1.

Case 3 was carried out in accordance with the process of the presentinvention, utilizing a first single reactor stage and a second stagehaving two additional reactors operated globally countercurrently andlocally cocurrently, with the gas flow rate split as illustrated inTable 3. As shown, the process in accordance with the present invention(Case 3) clearly performs better than Cases 1 and 2 for sulfur compoundconversion and final sulfur content while utilizing a reactor systemhaving the same volume. Case 4 is the same as Case 1 and is presentedfor comparison to Case 5 wherein a process in accordance with thepresent invention was operated to obtain the same sulfur content fromthe same reactor volume as the conventional scheme for process so as toillustrate the potential increase in reactor capacity by utilizing theprocess of the present invention. By adjusting the process to obtainsubstantially the same final sulfur content, the same reactor volume isable to provide more than double the Diesel treatment capacity ascompared to the conventional process.

EXAMPLE 3

In this example, a process in accordance with the present invention wascompared to a globally countercurrent and locally cocurrent process.Each process was utilized having 4 reactors with the same catalyst, aDiesel feed, and operating at a temperature of 320° C., a pressure of478 psi, and a ratio of hydrogen to feed of 104 Nm³/m³. FIG. 4 shows theresults in terms of sulfur content in the final product as a function ofrelative reactor volume. As shown, the hybrid process of the presentinvention provides substantially improved results.

EXAMPLE 4

In this example, two processes were evaluated. The first was a processin accordance with a preferred embodiment of the present inventionwherein cold separators were positioned after each reactor for recyclingcondensed vapors. For the same reactors, feed, temperature, pressure andhydrogen/feed ratio, FIG. 5 illustrates the relation between finalsulfur content and relative reactor volume for a process in accordancewith the present invention using cold separators (curve 1), as comparedto a process in accordance with the present invention without coldseparators (curve 2). As shown, the use of cold separators providesadditional benefit in reducing the final sulfur content by allowingsufficient hydrodesulfurization of all sulfur species, even those thatgo into the gas phase.

EXAMPLE 5

In this example, a comparison is presented showing final sulfur contentas a function of relative reactor volume for a conventional cocurrentprocess, for a two stage process using an inter-stage stripper, and fora process in accordance with the present invention. The feedstock,temperature, pressure and hydrogen/feed ratio were maintained the same,and the results are illustrated in FIG. 6. As shown, the process of thepresent invention provides better results in terms of final sulfurcontent than either of the other two processes.

EXAMPLE 6

In this example, the importance of the proper distribution of hydrogenfeed to the first stage and second stage in the process of the presentinvention is demonstrated.

An example is provided to evaluate hydrogen distribution using ahydrogen feed of 50% to the first stage, and a hydrogen feed of 50% tothe last reactor of the second stage. This was compared to a case runusing the same equipment and total gas volume, with an 80% feed to thefirst stage and a 20% feed to the second stage.

FIG. 7 shows the results in terms of outlet sulfur content as a functionof relative reactor volume for the process in accordance with thepresent invention and for the 80/20 hydrogen distribution. As shown, inthis instance the 50/50 distribution provides better results.

EXAMPLE 7

In this example, the importance of the distribution of catalyst betweenthe first and second stages is illustrated. A four reactor setup inaccordance with the present invention, with one reactor in the firststage and three reactors operated globally countercurrent and locallycocurrent in the second stage was used. In one evaluation according tothe present invention, 30% of the total catalyst volume was positionedin the first reactor, and 70% of the total catalyst volume was dividedequally among the three reactors of the second stage.

For comparison, the same system was operated providing 70% of totalcatalyst volume in the first stage, and 30% of catalyst volume in thesecond stage.

FIG. 8 shows the results in terms of sulfur content as a function ofrelative reactor volume for the 30/70 process of the present inventionas compared to the 70/30 process. As shown, the process of the presentinvention provides significantly better results.

EXAMPLE 8

In this example, the hydrogen partial pressure was evaluated, as afunction of dimensionless reactor length, for a process in accordancewith the present invention and for a pure cocurrent process.

FIG. 9 shows the results of this evaluation, and shows that the processin accordance with the present invention provides for significantlyincreased hydrogen partial pressure at the end of the reactor, which isdesirable. This provides for higher hydrogen partial pressures so as toprovide reacting conditions that are most suited for reacting the mostdifficult-to-react sulfur species, thereby providing conditions forenhanced hydrodesulfurization, particularly as compared to the purecocurrent case.

EXAMPLE 9

In this example, a comparison is provided for temperature as a functionof dimensionless reactor length for a pure cocurrent process, a purecountercurrent process and the hybrid process of the present invention.

For the same reactor volume, catalyst volume and hydrogen/feed ratio,FIG. 10 shows the resulting temperatures over dimensionless reactorlength. As shown, the countercurrent process has the highesttemperatures. Further, the hybrid process of the present invention isquite similar in temperature profile to that of the pure cocurrentprocess, with the exception that there is a slight decrease intemperature toward the reactor outlet.

This is beneficial since the higher temperatures, particularly thoseexperienced with countercurrent process, serve to accelerate catalystdeactivation.

EXAMPLE 10

In this example, the sulfur content as a function of relative reactorvolume was evaluated for a process in accordance with the presentinvention, a pure cocurrent process and a globally countercurrentprocess for a VGO feedstock with a process using a four reactor train,with the same feedstock, and a temperature of 340° C., a pressure of 760psi and a hydrogen/feed ratio of 273 Nm³/m³. FIG. 11 shows the resultsof this evaluation, and shows that the process of the present inventionperforms substantially better than the pure cocurrent and purecountercurrent processes, especially in the range of resulting sulfurcontent which is less than 50 wppm.

In accordance with the foregoing, it should be readily apparent that theprocess and system of the present invention provide for substantialimprovement in hydrodesulfurization processes which can be utilized toreduce sulfur content in hydrocarbon feeds with reactor volumesubstantially the same as conventional ones, or to substantiallyincrease reactor capacity from the same reactor volume at substantiallythe same sulfur content as can be accomplished utilizing conventionalprocesses.

It is to be understood that the invention is not limited to theillustrations described and shown herein, which are deemed to be merelyillustrative of the best modes of carrying out the invention, and whichare susceptible of modification of form, size, arrangement of parts anddetails of operation. The invention rather is intended to encompass allsuch modifications which are within its spirit and scope as defined bythe claims.

1. A system for hydroprocessing a hydrocarbon feed, comprising: a firsthydroprocessing zone containing a hydroprocessing catalyst and having aninlet for cocurrently receiving a hydrocarbon feed and a firsthydrogen-containing gas phase, said first hydroprocessing zone producinga first liquid hydrocarbon product and a gas phase containing hydrogenreaction products, hydrogen and volatile hydrocarbon fractions; aplurality of additional hydroprocessing zones each containing ahydroprocessing catalyst and including a final zone and an upstreamzone, said upstream zone having an inlet for cocurrently receiving saidfirst liquid hydrocarbon product from said first hydroprocessing zoneand a recycled hydrogen-containing gas phase, and said upstream zoneproducing an intermediate product; a liquid gas separator having aninlet for receiving the intermediate product and producing a separatedgas phase containing hydrogen reaction products, hydrogen and volatilehydrocarbon product and a liquid intermediate hydrocarbon product, saidfinal zone having an inlet for cocurrently receiving said liquidintermediate hydrocarbon product from said upstream hydroprocessing zonecocurrently with a second hydrogen-containing gas phase; and a furtherseparator having an inlet for receiving said gas phase and saidseparated gas phase so as to produce a separated liquid phase containingsaid volatile hydrocarbon fractions and a gas phase containing saidhydrogen reaction products and hydrogen; a separator for receiving aproduct from said final hydroprocessing zone and for separating saidproduct into a hydrocarbon phase and said recycled hydrogen-containinggas phase, wherein said final zone, said separator, said upstream zone,and said liquid gas separator are connected for gas flow in series todefine a flow path of hydrogen gas only in a single direction from saidfinal zone to said separator, from said separator to said upstream zone,from said upstream zone to said liquid gas separator and from saidliquid gas separator to said further separator.
 2. The system of claim1, wherein said first hydroprocessing zone is a hydrodesulfurizationzone containing a hydrodesulfurization catalyst.
 3. The system of claim1, wherein said additional hydroprocessing zones comprise at least oneadditional hydrodesulfurization zone containing a hydrodesulfurizationcatalyst.
 4. The system of claim 1, wherein each of said firsthydroprocessing zone and said additional hydroprocessing zones is ahydrodesulfurization zone containing a hydrodesulfurization catalyst.